Hydrocarbon fuels generally contain sulfur in the form of organosulfur compounds at sulfur concentrations ranging from less than 10 ppm to greater than 1% by weight. When the fuel is combusted in internal combustion engines, the sulfur is emitted as sulfur oxides (SOx), which are primary constituents of acid rain. The presence of sulfur has a significant effect on the amount of particulate matter (PM) emitted from diesel engines, as sulfur acts as an initiator for soot formation. Nitrogen oxide (NOx) emissions from engines are also affected by the sulfur content of the fuel, because sulfur adversely affects NOx emission control catalysts. In advanced power generation devices, such as fuel cells, sulfur acts as a poison for many of the catalytic components of the fuel cell, thereby limiting the applicability of these devices.
There is a well-established hierarchy to the ease with which various organosulfur compounds can be removed from petrochemical streams. Simple aliphatic, naphthenic, and aromatic mercaptans, sulfides, di- and polysulfides and the like surrender their sulfur more readily than the class of heterocyclic sulfur compounds comprised of thiophene and its higher homologs and analogs. Within the generic thiophenic class, desulfurization reactivity decreases with increasing molecular structure and complexity. While simple thiophenes represent the more labile sulfur types, the other extreme, sometimes referred to as “refractory sulfur” is represented by the derivatives of dibenzothiophene, especially those mono- and di-substituted dibenzothiophenes bearing substituents on the carbons beta to the sulfur atom. These highly refractory sulfur heterocycles resist desulfurization as a consequence of steric hindrance that precludes the requisite catalyst-substrate interaction. For this reason, these materials survive traditional desulfurization processes and may poison subsequent processes whose operability is sulfur sensitive.
Techniques for the removal of sulfur from hydrocarbon fuels can be divided into the following four general categories: 1) hydrodesulfurization, which can be characterized by the conversion of organically bound sulfur to H2S in the presence of hydrogen; 2) cracking, which can be characterized by the conversion of organically bound sulfur to H2S; 3) chemical absorption, which can be characterized by the abstraction of sulfur from the fuel at moderate temperature; and 4) physical absorption, which can be characterized by the removal of sulfur-containing compounds from the fuel at low temperature.
Prior to use, petroleum distillates are generally hydrotreated (hydrodesulfurized) to reduce the concentration of sulfur compounds. In the hydrodesulfurization (HDS) process, the petroleum distillate is treated with excess hydrogen at high pressure and elevated temperature over a catalyst. The catalyst typically is based on cobalt-molybdenum sulfides or on nickel-molybdenum sulfides, with additives known in the art. Under HDS conditions, organosulfur compounds react with hydrogen to produce H2S and smaller organic fragments, and aromatics are hydrogenated. Deeply-hydrotreated petroleum products, such as those sold in the U.S. and Europe, contain sulfur mainly in the fractions boiling above approximately 300° C. These compounds are the alkylated dibenzothiophenes, and those with alkylation on the carbon next to the sulfur atom are most difficult to remove by HDS.
While HDS is well suited for large stationary applications, it does not readily lend itself to distributed power generation applications due to system size, cost and complexity. High-pressure hydrogen (greater than 500 psig or greater than about 3.5 MPa) is generally necessary when using HDS to perform deep desulfurization of the feedstock, necessitating an auxiliary supply of hydrogen or significant hydrogen recycle if the desulfurization system is coupled to a fuel reformer to generate hydrogen. Destruction of the most refractory sulfur species can be accomplished under relatively severe process conditions, but this may prove to be undesirable owing to the onset of harmful side reactions leading to high aromatic content and carbonaceous deposits.
The drawbacks of HDS include the following: 1) the sensitivity of the catalyst to a great many subtle process parameters, any of which may reduce its lifetime and/or activity; 2) the necessity of pretreating the catalyst with a sulfur-containing stream prior to use in order to form the required metal sulfide phases; 3) the non-regenerable nature of the catalyst; 4) the large quantities of high-pressure hydrogen that are required to push the HDS reaction to completion; and 5) the difficulty of removing alkylated dibenzothiophenes by this process, particularly in terms of requiring conditions that are much more severe and that substantially raise the fuel cost and reduce fuel production rates. The severe conditions needed for the removal of alkylated dibenzothiophenes include requirements of pressures greater than 1000 psig (7.0 MPa) as well as greater hydrogen supply to the HDS process.
Sulfur can also be removed from hydrocarbon fuel by thermally or catalytically cracking the organosulfur compounds into H2S and other small hydrocarbon fragments, for example by contacting a hydrocarbon stream with a fluidized bed of an acidic catalyst.
A drawback to the use of HDS or cracking for desulfurization is that in applications distanced from a refinery (distributed or small- to mid-scale power generation), the byproduct H2S must be converted to a more benign species prior to disposal or emission. Separation of the hydrogen sulfide from a desulfurized liquid fuel stream can be carried out in a liquid-gas separator or by using alkaline absorbents. Other approaches to H2S separation include the use of a solvent specific for H2S to transport H2S out of a gas stream, the use of a H2S-permeable membrane to effect the separation, and the use of molecular sieves to absorb H2S from a gas stream and release it to an effluent stream.
Removal of H2S from the desulfurized hydrocarbon fuel stream may also be accomplished through chemical absorption of the H2S. Much of the existing art for removal of H2S from a petroleum-based feed gas stream focuses on the use of a transition metal oxide that absorbs H2S at moderately high temperatures (200-600° C.) according to the following reaction:MOx+xH2S→MSx+xH2O,  (1)where M is commonly Zn, Cu, Ni, or Fe.
In theory, the absorbent may be regenerated by air oxidation of the metal sulfide according to the following reaction:MSx+3x/2O2→MOx+xSO2.  (2)However, the metal sulfate is commonly an intermediate when the regeneration is carried out at low to moderate temperatures, and is a thermodynamic sink. This limits the use of the metal oxide absorbent to only one or a few regeneration cycles if regeneration is to occur at moderate temperatures. Temperatures in excess of 625° C. are required to regenerate ZnO from ZnS without formation of ZnSO4. Zinc oxide absorbents are the most popular for removal of H2S from, for example, hot sour gas streams. Zinc titanate based absorbents have been shown to be slightly more regenerable than ZnO.
Hydrogen sulfide absorbents that bind hydrogen sulfide through physical adsorption may also be used to remove H2S from fuel streams. These absorbents are generally regenerable through manipulation of the process temperature, pressure, and/or gas rate so that the absorbent cycles between adsorption and desorption stages. Such absorbents may include zeolitic materials, spinels, meso- and microporous transition metal oxides, particularly oxides of the fourth period of the Periodic Chart of the Elements.
Direct chemical absorption of organosulfur compounds without use of H2S intermediates is the third manner in which sulfur-containing fuels can be desulfurized. Some of these direct chemical absorption methods occur in the presence of hydrogen supplied via a hydrogen co-feed, and regeneration of the absorbent may require a particularly high temperature and an absorbent reduction step prior to re-use of the absorbent. Some of the absorbents useful for H2S absorption have also been shown to be applicable to this direct desulfurization technique. Zinc oxide, manganese oxide and iron oxide have been cited as useful absorbents. While a number of references that discuss direct chemical absorption disclose that metal and metal oxide absorbents can be used to desulfurize fuels, these references do not disclose regenerability of these types of absorbents, and the applicability of direct chemical absorption methods to desulfurization of substituted dibenzothiophenic compounds is not disclosed.
Low-temperature physical absorption of organosulfur compounds is another manner in which the sulfur content of hydrocarbon streams can be reduced. For example, one method uses zeolites and clays to remove sulfur-containing compounds from gasoline at ambient temperature. Unless provisions are made to regenerate the low-temperature absorbent beds, these systems may become prohibitively large when processing high sulfur content fuels.